Vanguard Natural Resources, LLC Reports Second Quarter 2014 Results

HOUSTON--()--Vanguard Natural Resources, LLC (NASDAQ: VNR) (“Vanguard” or “the Company”) today reported financial and operational results for the quarter ended June 30, 2014.

Mr. Scott W. Smith, President and CEO, commented, “We are very pleased to announce the $278 million East Texas and North Louisiana acquisition that will be immediately accretive to Vanguard’s cash flow upon close. This acquisition features both mature, long life natural gas and oil properties along with an inventory of low risk behind pipe development projects and a drilling inventory of vertical and potentially horizontal wells that can be developed over the next several years. This transaction is an excellent addition to our current portfolio of assets and establishes another core area from which we can continue to build upon in the future.”

         
Three Months Ended Six Months Ended
June 30, June 30,
2014     2013 2014     2013
($ in thousands, except per unit data)
(Unaudited)
Production (MMcfe/d) 315 219 292 209
Oil, natural gas and natural gas liquids sales $ 161,519 $ 116,737 $ 314,259 $ 213,419
Net gains (losses) on commodity derivative contracts $ (38,398 ) $ 58,595 $ (94,436 ) $ 29,320
Operating expenses $ 50,822 $ 36,473 $ 96,278 $ 69,989
Selling, general and administrative expenses $ 7,864 $ 6,900 $ 15,902 $ 13,449
Depreciation, depletion, amortization, and accretion $ 51,508 $ 42,911 $ 95,118 $ 81,604
Net Income (Loss) Attributable to Common and Class B
Unitholders $ (9,333 ) $ 81,149 $ 3,825 $ 54,126
Adjusted Net Income Attributable to Common and Class B

Unitholders (1)

$ 21,965 $ 19,102 $ 46,568 $ 35,990
Adjusted Net Income Attributable to Common and Class B

Unitholders, per unit (1)

$ 0.27 $ 0.27 $ 0.59 $ 0.53
Adjusted EBITDA(1) $ 97,690 $ 80,282 $ 187,552 $ 152,714
Interest expense, including settlements paid on interest
rate derivative contracts $ 17,564 $ 16,925 $ 34,813 $ 33,310
Estimated maintenance capital expenditures $ 31,337 $ 14,770 $ 60,151 $ 29,418
Distributions to Preferred unitholders $ 4,596 $ 152 $ 6,558 $ 152
Distributable Cash Flow Available to Common and Class B

Unitholders (1)

$ 46,143 $ 48,435 $ 87,980 $ 89,834
Distributable Cash Flow per common and Class B unit (1) $ 0.57 $ 0.65 $ 1.09 $ 1.25
Common and Class B unit distribution coverage (1) 0.90x 1.05x 0.87x 1.03x
Weighted average common and Class B units outstanding at
record date attributable to distribution period 81,344 74,821 80,608 71,652
 
   
(1) Non-GAAP financial measures. Please see Adjusted Net Income Attributable to Common and Class B Unitholders, Adjusted EBITDA and Distributable Cash Flow Available to Common and Class B Unitholders tables at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure.
 

Second Quarter 2014 Highlights:

  • Adjusted EBITDA (a non-GAAP financial measure defined below) increased 22% to $97.7 million in the second quarter of 2014 from $80.3 million in the second quarter of 2013 and increased 9% from the $89.9 million recorded in the first quarter of 2014.
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) decreased 5% to $46.1 million from the $48.4 million generated in the second quarter of 2013 and increased 10% from the $41.8 million generated in the first quarter of 2014.
  • We reported a net loss attributable to common and Class B unitholders for the quarter of $9.3 million or $(0.12) per basic unit compared to a reported net income of $81.1 million or $1.14 per basic unit in the second quarter of 2013.
  • Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $22.0 million in the second quarter of 2014, or $0.27 per basic unit, as compared to $19.1 million, or $0.27 per basic unit, in the second quarter of 2013. The second quarter of 2014 includes net non-cash losses of $31.3 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The second quarter of 2013 results included net non-cash gains of $62.2 million.
  • Reported average production of 315 MMcfe per day in the second quarter of 2014, up 44% over 219 MMcfe per day produced in the second quarter of 2013 and an 18% increase over 268 MMcfe per day produced in the first quarter of 2014. On an Mcfe basis, crude oil, natural gas and natural gas liquids (“NGLs”) accounted for 17%, 68%, and 15% of our second quarter 2014 production, respectively.

During the quarter, we produced 19,649 MMcf of natural gas, an increase of 49% from the 13,176 MMcf of natural gas produced in the second quarter of 2013, 806 MBbls of oil, an increase of 1% from the 798 MBbls of oil produced in the second quarter of 2013, and 696 MBbls of NGLs, an increase of 114% from the 326 MBbls of NGLs produced in the second quarter of 2013.

Including the impact of our natural gas hedges in the second quarter of 2014, we realized an average price of $3.48 per Mcf on natural gas sales, compared to the unhedged realized average price of $3.55 per Mcf. Our hedged realized average price for oil was $84.40 per barrel, compared to the unhedged realized average price of $91.74 per barrel. The impact of our NGL hedges resulted in an average realized price of $25.37 per barrel of NGLs sales, compared to the unhedged realized average price of $25.49 per barrel.

2014 Six Month Highlights:

  • Adjusted EBITDA (a non-GAAP financial measure defined below) increased 23% to $187.6 million in the first half of 2014 from $152.7 million in the first half of 2013.
  • Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) for the first six months of 2014 decreased 2% to $88.0 million from the $89.8 million generated in the first half of 2013.
  • We reported net income attributable to common and Class B unitholders for the first six months of 2014 of $3.8 million or $0.05 per basic unit compared to a reported net income of $54.1 million or $0.80 per basic unit in the first half of 2013.
  • Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $46.6 million for the first six months of 2014, or $0.59 per basic unit, as compared to $36.0 million, or $0.53 per basic unit, in the comparable period of 2013. The 2014 results include net non-cash charges of $42.7 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. Results for the first half of 2013 included net non-cash gains of $18.9 million.
  • Reported average production of 292 MMcfe per day in the first six months of 2014, up 40% over 209 MMcfe per day produced in the first six months of 2013. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 18%, 68%, and 14% of our production for the first six months of 2014, respectively.

During the first six months of 2014, we produced 35,689 MMcf of natural gas, an increase of 42% from the 25,167 MMcf of natural gas produced in the first six months of 2013, 1,581 MBbls of oil, an increase of 4% from the 1,523 MBbls of oil produced in the first six months of 2013, and 1,268 MBbls of NGLs, an increase of 118% from the 583 MBbls of NGLs produced in the first six months of 2013.

Including the impact of our natural gas hedges in the first six months of 2014, we realized an average price of $3.45 per Mcf on natural gas sales, compared to the unhedged realized average price of $3.74 per Mcf. Our hedged realized average price for oil was $84.36 per barrel, compared to the unhedged realized average price of $89.90 per barrel. The impact of our NGL hedges resulted in an average realized price of $30.10 per barrel of NGLs sales, compared to the unhedged realized average price of $30.55 per barrel.

Capital Expenditures

Total capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $36.4 million in the second quarter of 2014 compared to $14.8 million for the comparable quarter of 2013 and $31.2 million for the first quarter of 2014. Estimated maintenance capital expenditures in the second quarter of 2014 totaled $31.3 million. The balance of $5.1 million was attributable to growth capital expenditures associated with the Pinedale Acquisition in the Green River Basin during the second quarter of 2014. Total capital expenditures were approximately $67.7 million for the first six months of 2014 compared to $29.4 million in the comparable period of 2013.

We currently anticipate a total capital expenditures budget for the remainder of 2014 to range between $65.0 million and $70.0 million, excluding any potential future acquisitions. We expect to spend approximately 60% of the remaining 2014 capital budget on the newly acquired assets in the Pinedale Acquisition in the Green River Basin, participating as a non-operated partner in the drilling and completion of vertical natural gas wells. Additionally, we expect to spend approximately 20% of the remaining 2014 capital budget in the Permian Basin, 5% in the Big Horn Basin and the balance in our other operating areas.

Recent Activities

Acquisitions

On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and a net cash consideration of $9.6 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility and is subject to customary final post-closing adjustments to be determined based on an effective date of January 1, 2014.

On July 30, 2014, we entered into a purchase and sale agreement to acquire natural gas and oil properties in North Louisiana and East Texas for a purchase price of $278.0 million from an undisclosed seller. The properties consist of approximately 23,000 net acres that are currently producing approximately 17.5 MMcfe per day with approximately 67% natural gas and 33% oil and NGLs. Based on internal estimates, total proved reserves being acquired are approximately 150 Bcfe of which 57% are currently proved developed. The effective date of the acquisition is June 1, 2014 and we anticipate closing this acquisition on or before October 1, 2014. We intend to fund this acquisition with borrowings under our existing reserve-based credit facility.

Non-Operated Permian Activity

We signed an agreement with Athlon Energy where Athlon will carry Vanguard for five oil wells (two in Andrews County, Texas and three in Glasscock County, Texas) with a working interest of approximately 30%. One well in Andrews County and one well in Glasscock County have already been drilled and are currently waiting on completion. The third well is expected to begin drilling in September. We anticipate that all five wells under this agreement will be completed by the end of the year.

Additional non-operated activity has occurred with the drilling and completion of the Caprock St #1H in the Lockridge Block of Ward County, Texas operated by Atlantic Exploration, LLC. This well began flowing back in late July and Vanguard has an approximate 24% working interest. Initial results have been very good with a high seven day average IP rate of approximately 750 barrels of oil per day and 1,050 Mcf per day. Diamondback Energy, Inc has also drilled the Brown & Martin 21-1H well in Dawson County and completions are currently underway. Vanguard has approximately a 16.4% working interest in this well.

Hedging Activities

We enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. We have mitigated some of the volatility on our cash flow price with derivative contracts through 2017 for oil and natural gas production and through 2015 for NGLs production. Specifically, we have implemented a hedging program for approximately 85% of our anticipated production of crude oil through 2015, approximately 80% of our natural gas production through 2017 and approximately 6% of our NGLs production through 2015. At June 30, 2014, the fair value of commodity derivative contracts was a liability of approximately $2.9 million, of which $22.8 million of net current liability settles during the next twelve months. Currently, we use fixed-price swaps, basis swap contracts, three-way collars, swaptions, call options sold, put options sold and range bonus accumulators to hedge oil, natural gas and NGLs prices.

New commodity derivative contracts put in place during the three months ended June 30, 2014 are as follows:

                 
Year Year Year Year
2014 2015 2016 2017
Gas Positions:
Three-Way Collars
Notional Volume (MMBtu) 2,450,000

-

-

-

Floor Price ($/MMBtu) $ 4.21 $

-

$

-

$

-

Ceiling Price ($/MMBtu) $ 5.00 $

-

$

-

$

-

Put Sold ($/MMBtu) $ 3.50 $

-

$

-

$

-

Basis Swaps

Northwest Rocky Mountain Pipeline and NYMEX Henry

Hub Basis Differential

Notional Volume (MMBtu)

-

-

14,640,000 10,950,000
Fixed Price ($/MMBtu) $

-

$

-

$ (0.21 ) $ (0.22 )
 
Oil Positions:
Three-Way Collars
Notional Volume (Bbls)

-

733,000 366,000

-

Floor Price ($/Bbl) $

-

$ 92.35 $ 90.00 $

-

Ceiling Price ($/Bbl) $

-

$ 98.79 $ 98.11 $

-

Put Sold ($/Bbl) $

-

$ 76.63 $ 77.50 $

-

 

For a summary of all commodity and interest rate derivative contracts in place at June 30, 2014, please refer to our Quarterly Report on Form 10-Q which is expected to be filed on or about August 5, 2014.

Liquidity Update

As of July 31, 2014, there were $715.0 million of outstanding borrowings and $807.2 million of borrowing capacity under the reserve-based credit facility, after consideration of a $2.8 million reduction in availability for letters of credit and a $1.525 billion borrowing base. We also have approximately $10.0 million in available cash.

Total net proceeds received under our At-The-Market (“ATM”) Equity Program were approximately $34.6 million, $65.9 million and $32.6 million, after commissions, for the first quarter 2014, second quarter 2014 and July 2014, respectively. In total for 2014, we have raised net proceeds of $133.1 million, after commissions, from the sales of 4,360,247 common units. Additionally, we raised $0.7 million, after commissions, from the sales of 28,034 Series A Preferred Units during 2014.

Cash Distributions

On July 16, 2014, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of June 2014 of $0.21 per common and Class B unit ($2.52 on an annualized basis) expected to be paid on August 14, 2014 to Vanguard unitholders of record on August 1, 2014.

Also on July 16, 2014, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Preferred Unit and $0.15885 per Series B Preferred Unit to be paid on August 15, 2014 to Vanguard preferred unitholders of record on August 1, 2014.

Conference Call Information

Vanguard will host a conference call on Tuesday (August 5, 2014) to discuss its second quarter 2014 financial results, at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial (888) 389-5988 or (719) 325-2448, for international callers, using access code 6783598 and ask for the “Vanguard Natural Resources Earnings Call.” The conference call will also be broadcast live via the Internet and can be accessed through the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com.

A telephonic replay of the conference call will be available until September 4, 2014 and may be accessed by calling (888) 203-1112 or (719) 457-0820, for international callers, and using access code 6783598. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.com.

About Vanguard Natural Resources, LLC

Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of oil and natural gas properties. Vanguard’s assets consist primarily of producing and non-producing oil and natural gas reserves located in the Permian Basin in West Texas and New Mexico, the Green River Basin in Wyoming, the Big Horn Basin in Wyoming and Montana, the Arkoma Basin in Arkansas and Oklahoma, the Gulf Coast Basin in Texas and Mississippi, the Piceance Basin in Colorado, the Williston Basin in North Dakota and Montana, the Wind River Basin in Wyoming, and the Powder River Basin in Wyoming. More information on Vanguard can be found at www.vnrllc.com.

Forward-Looking Statements

This press release includes “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include but are not limited to statements about the acquisition announced in this press release. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for oil, natural gas and NGLs, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the Securities and Exchange Commission. Please see “Risk Factors” in the Company’s public filings.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to publicly correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

         
VANGUARD NATURAL RESOURCES, LLC

Operating Statistics (a)

(Unaudited)
 
Three Months Ended Six Months Ended June
June 30, 30,
2014     2013 2014     2013
Average realized prices, excluding hedges:
Oil (Price/Bbl) $ 91.74 $ 87.38 $ 89.90 $ 84.19
Natural Gas (Price/Mcf) $ 3.55 $ 2.73 $ 3.74 $ 2.52
NGLs (Price/Bbl) $ 25.49 $ 33.85 $ 30.55 $ 37.17
Average realized prices, including hedges (b):
Oil (Price/Bbl) $ 84.40 $ 86.31 $ 84.36 $ 82.96
Natural Gas (Price/Mcf) $ 3.48 $ 3.17 $ 3.45 $ 3.34
NGLs (Price/Bbl) $ 25.37 $ 34.23 $ 30.10 $ 37.41
Average NYMEX prices:
Oil Price (Price/Bbl) $ 103.01 $ 94.20 $ 100.89 $ 94.26
Natural Gas Price (Price/Mcf) $ 4.67 $ 4.09 $ 4.86 $ 3.73
Total production volumes:
Oil (MBbls) 806 798 1,581 1,523
Natural Gas (MMcf) 19,649 13,176 35,689 25,167
NGLs (MBbls) 696 326 1,268 583
Combined (MMcfe) 28,664 19,916 52,786 37,802
Average daily production volumes:
Oil (Bbls/day) 8,860 8,765 8,737 8,414
Natural Gas (MMcf/day) 216 145 197 139
NGLs (Bbls/day) 7,652 3,579 7,007 3,220
Combined (MMcfe/day) 315 219 292 209
 
   
(a) During 2014 and 2013, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition forward.
 
(b) Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.
 
 
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
 
      Three Months Ended     Six Months Ended
June 30, June 30,
2014     2013 2014     2013
Revenues:
Oil sales $ 73,963 $ 69,701 $ 142,163 $ 128,217
Natural gas sales 69,806 36,010 133,348 63,534
NGLs sales 17,750 11,026 38,748 21,668
Net gains (losses) on commodity derivative contracts (38,398 ) 58,595   (94,436 ) 29,320  
Total revenues 123,121   175,332   219,823   242,739  
 
Costs and expenses:
Production:
Lease operating expenses 34,293 26,509 64,715 50,682
Production and other taxes 16,529 9,964 31,563 19,307
Depreciation, depletion, amortization, and accretion 51,508 42,911 95,118 81,604
Selling, general and administrative expenses 7,864   6,900   15,902   13,449  
Total costs and expenses 110,194   86,284   207,298   165,042  
 
Income from operations 12,927   89,048   12,525   77,697  
 
Other income (expense):
Interest expense (16,549 ) (15,963 ) (32,808 ) (31,401 )
Net gains (losses) on interest rate derivative contracts (1,121 ) 2,412 (1,579 ) 2,127
Gains on acquisitions of oil and natural gas properties

-

5,827 32,114 5,827
Other 6   (23 ) 131   28  
Total other income (expense) (17,664 ) (7,747 ) (2,142 ) (23,419 )
Net income (loss) $ (4,737 ) $ 81,301 $ 10,383 $ 54,278
Distributions to Preferred unitholders (4,596 ) (152 ) (6,558 ) (152 )
Net income (loss) attributable to Common and
Class B unitholders $ (9,333 ) $ 81,149   $ 3,825   $ 54,126  
 
Net income (loss) per Common and Class B unit –
basic and diluted $ (0.12 ) $ 1.14   $ 0.05   $ 0.80  
 
Weighted average Common units outstanding
Common units – basic & diluted 80,536   70,798   79,865   67,601  
Class B units – basic & diluted 420   420   420   420  
 
         
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
 
June 30, December 31,
2014 2013
(Unaudited)
Assets
Current assets
Cash and cash equivalents $ 22,113 $ 11,818
Trade accounts receivable, net 91,337 70,109
Derivative assets 9,432 21,314
Other current assets 3,597   2,916  
Total current assets 126,479   106,157  
 
Oil and natural gas properties, at cost 3,213,473 2,523,671
Accumulated depletion, amortization and impairment (804,814 ) (713,154 )
Oil and natural gas properties evaluated, net – full cost method 2,408,659   1,810,517  
 
Other assets
Goodwill 420,955 420,955
Derivative assets 25,030 60,474
Other assets 29,196   91,538  
Total assets $ 3,010,319   $ 2,489,641  
 
Liabilities and members’ equity
Current liabilities
Accounts payable:
Trade $ 18,051 $ 9,824
Affiliates 401 249
Accrued liabilities:
Lease operating 14,905 12,882
Development capital 19,894 10,543
Interest 11,646 11,989
Production and other taxes 23,371 16,251
Derivative liabilities 35,794 10,992
Oil and natural gas revenue payable 21,627 23,245
Distribution payable 17,996 16,499
Other 13,882   12,929  
Total current liabilities 177,567 125,403
 
Long-term debt 1,273,011 1,007,879
Derivative liabilities 7,931 4,085
Asset retirement obligations, net of current portion 106,775 82,208
Other long-term liabilities

-

  1,731  
Total liabilities 1,565,284   1,221,306  
Commitments and contingencies
Members’ equity

Series A Preferred units, 2,561,661 units issued and outstanding at June 30, 2014 and

2,535,927 at December 31, 2013

61,682 61,021
Series B Preferred units, 7,000,000 units issued and outstanding at June 30, 2014 169,265

-

Common units, 82,017,879 units issued and outstanding at June 30, 2014
and 78,337,259 at December 31, 2013 1,206,473 1,199,699
Class B units, 420,000 issued and outstanding at June 30, 2014
and December 31, 2013 7,615   7,615  
Total members’ equity 1,445,035   1,268,335  
Total liabilities and members’ equity $ 3,010,319   $ 2,489,641  

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) plus the following adjustments:

  • Net interest expense;
  • Depreciation, depletion, amortization, and accretion;
  • Net gains or losses on commodity derivative contracts;
  • Cash settlements on matured commodity derivative contracts;
  • Net gains or losses on interest rate derivative contracts;
  • Net gains and losses on acquisition of oil and natural gas properties;
  • Texas margin taxes;
  • Compensation related items, which include unit-based compensation expense and unrealized fair value of phantom units granted to officers; and
  • Material transaction costs incurred on acquisitions.

Adjusted EBITDA is a significant performance metric used by management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and operating income (loss) and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. For example, we fund premiums paid for derivative contracts, acquisitions of oil and natural gas properties, including the assumption of derivative contracts related to these acquisitions, and other capital expenditures primarily with proceeds from debt or equity offerings or with borrowings under our Reserve-Based Credit Facility. For the purposes of calculating Adjusted EBITDA, we consider the cost of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investments related to our underlying oil and natural gas properties; therefore, they are not deducted in arriving at our Adjusted EBITDA. Our Consolidated Statements of Cash Flows, prepared in accordance with GAAP, present cash settlements on matured derivatives and the initial cash outflows of premiums paid to enter into derivative contracts as operating activities. When we assume derivative contracts as part of a business combination, we allocate a part of the purchase price and assign them a fair value at the closing date of the acquisition. The fair value of the derivative contracts acquired is recorded as a derivative asset or liability and presented as cash used in investing activities in our Consolidated Statements of Cash Flows. As the volumes associated with these derivative contracts, whether we entered into them or we assumed them, are settled, the fair value is recognized in operating cash flows. Whether these cash settlements on derivatives are received or paid, they are reported as operating cash flows which may increase or decrease the amount we have available to fund distributions.

However, for purposes of calculating Adjusted EBITDA, we consider both premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities. This is similar to the way the initial acquisition or development costs of our oil and natural gas properties are presented in our Consolidated Statements of Cash Flows; the initial cash outflows are presented as cash used in investing activities, while the cash flows generated from these assets are included in operating cash flows. The consideration of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities for purposes of determining our Adjusted EBITDA differs from the presentation in our consolidated financial statements prepared in accordance with GAAP which (i) presents premiums paid for derivatives entered into as operating activities and (ii) the fair value of derivative contracts acquired as part of a business combination as investing activities.

Distributable Cash Flow Available to Common and Class B Unitholders

We present Distributable Cash Flow Available to Common and Class B Unitholders in addition to our reported net income (loss) in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income (loss) plus the following adjustments:

  • Net interest expense;
  • Depreciation, depletion, amortization, and accretion;
  • Net gains or losses on commodity derivative contracts;
  • Cash settlements on matured commodity derivative contracts;
  • Net gains or losses on interest rate derivative contracts;
  • Net gains and losses on acquisition of oil and natural gas properties;
  • Texas margin taxes;
  • Compensation related items, which include unit-based compensation expense and unrealized fair value on phantom units granted to officers; and
  • Material transaction costs incurred on acquisitions;

Less:

  • Estimated maintenance capital expenditures;
  • Distributions to Preferred unitholders;

Plus:

  • Proceeds from the sale of leasehold interests.

Distributable Cash Flow Available to Common and Class B Unitholders is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our monthly distribution rates. However, Distributable Cash Flow Available to Common and Class B Unitholders should not be viewed as indicative of the amount that we plan to distribute for a given period. Distributable Cash Flow Available to Common and Class B Unitholders is not intended to be a substitute for net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a metric commonly used by investors and the analyst community to assess our financial performance from period to period.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our GAAP net income, which is affected by non-cash items. As a result, we may be unable to pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses. Our board of directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of our limited liability company agreement. Management considers the timing and size of capital expenditures and long-term views about expected results in determining the amount of distributions. Capital spending and the resulting production and net cash provided by operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment. Consistent with practices common to publicly traded partnerships, our board of directors historically has not varied the distribution it declares period to period based on uneven available distributable cash flow. Our board of directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution. In instances following acquisitions and development activities, our board of directors reviews any excess in distributable cash flows after distributions to unitholders in those periods, as well as forecasts of expected future net cash flows to determine if increases in distributions could be made. If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, our board of directors may determine to reduce, suspend or discontinue paying distributions. Our board of directors may decide to retain the excess in distributable cash flows after distributions to unitholders for our future operations, future capital expenditures, future debt service or other future obligations. Any shortfalls are funded with cash on hand and/or with borrowings under our reserve-based credit facility.

               
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted EBITDA (a) and
Distributable Cash Flow Available to Common and Class B Unitholders
(Unaudited)
(in thousands, except per unit amounts)
 
Three Months Ended Six Months Ended
June 30, June 30,

2014

2013 2014 2013
Net income (loss) $ (4,737 ) $ 81,301 $ 10,383 $ 54,278
Plus:
Interest expense 16,549 15,963 32,808 31,401
Depreciation, depletion, amortization, and accretion 51,508 42,911 95,118 81,604
Net (gains) losses on commodity derivative contracts 38,398 (58,595 ) 94,436 (29,320 )
Cash settlements on matured commodity derivative contracts(b)(c) (7,410 ) 4,971 (19,380 ) 18,721
Net (gains) losses on interest rate derivative contracts(d) 1,121 (2,412 ) 1,579 (2,127 )
Gain on acquisition of oil and natural gas properties

-

(5,827 ) (32,114 ) (5,827 )
Texas margin taxes 130 76 (281 ) (241 )
Compensation related items 2,131 1,775 5,003 3,503
Material transaction costs incurred on acquisitions  

-

    119    

-

    722  
Adjusted EBITDA $ 97,690   $ 80,282   $ 187,552   $ 152,714  
Less:
Interest expense, including settlements paid on interest rate derivatives (17,564 ) (16,925 ) (34,813 ) (33,310 )
Estimated maintenance capital expenditures (e) (31,337 ) (14,770 ) (60,151 ) (29,418 )
Distributions to Preferred unitholders (4,596 ) (152 ) (6,558 ) (152 )
Proceeds from sale of leasehold interests   1,950    

-

    1,950    

-

 
Distributable Cash Flow Available to Common and Class B Unitholders $ 46,143 $ 48,435 $ 87,980 $ 89,834
Distributions to Common and Class B unitholders   51,247     46,015     101,365     87,595  
Excess (shortfall) of distributable cash flow after distributions to unitholders $ (5,104 ) $ 2,420   $ (13,385 ) $ 2,239  
 
Distributable Cash Flow per Common and Class B unit $ 0.57 $ 0.65 $ 1.09 $ 1.25
Common and Class B unit Distribution Coverage

0.90

x

1.05

x

0.87

x

1.03

x

 

(a)

Our Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and operating income (loss) and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

 

(b)

Excludes premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We consider the cost of premiums paid for derivatives as an investment related to our underlying oil and natural gas properties.

$

-

$ 55 $

-

$ 109
 

(c)

Excludes the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. We consider the amounts paid to sellers for derivative contracts assumed with business combinations a part of the purchase price of the underlying oil and natural gas properties.

$ 5,983 $ 7,504 $ 10,864 $ 15,428
 

(d)

Includes settlements paid on interest rate derivatives

$ 1,015 $ 962 $ 2,005 $ 1,909
 

(e)

Estimated maintenance capital expenditures are intended to represent the amount of capital required to offset the decrease in cash flow from the prior year due to the change in natural gas, oil and NGLs prices and the decline in proved developed producing production. These costs, which are incorporated in our annual capital budget as approved by the board of directors, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing cash flow on both operated and non-operated properties. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our cash flow. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain cash flow at current levels, which could adversely affect our ability to pay a distribution at the current level or at all.

 

Adjusted Net Income Attributable to Common and Class B Unitholders

We present Adjusted Net Income Attributable to Common and Class B Unitholders in addition to our reported net income (loss) attributable to common and Class B unitholders in accordance with GAAP. Adjusted Net Income Attributable to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income attributable to Common and Class B unitholders plus the following adjustments:

  • Change in fair value of commodity derivative contracts;
  • Change in fair value of interest rate derivative contracts;
  • Unrealized fair value on phantom units granted to officers;
  • Fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period;
  • Gains on acquisition of oil and natural gas properties; and
  • Material transaction costs incurred on acquisitions.

This information is provided because management believes exclusion of the impact of these items will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the significant fluctuations that commodity price volatility has on our results, particularly as it relates to changes in the fair value of our derivative contracts. Adjusted Net Income Attributable to Common and Class B Unitholders is not intended to represent cash flows for the period, nor is it presented as a substitute for net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.

       
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) Attributable to Common and Class B Unitholders to
Adjusted Net Income Attributable to Common and Class B Unitholders
(in thousands, except per unit data)
(Unaudited)
 
Three Months Ended Six Months Ended
June 30, June 30,
  2014         2013     2014         2013  
Net Income (Loss) Attributable to Common and Class B Unitholders $ (9,333 ) $ 81,149 $ 3,825 $ 54,126
Plus (less):
Change in fair value of commodity derivative contracts 25,005 (61,183 ) 64,192 (26,136 )
Change in fair value of interest rate derivative contracts 106 (3,374 ) (426 ) (4,036 )
Unrealized fair value on phantom units granted to officers 204 714 227 1,713
Fair value of derivative contracts acquired that apply to
contracts settled during the period 5,983 7,504 10,864 15,428
Gain on acquisition of oil and natural gas properties

-

(5,827 ) (32,114 ) (5,827 )
Material transaction costs incurred on acquisitions  

-

    119    

-

    722  
Adjusted Net Income Attributable to Common and Class B Unitholders $ 21,965   $ 19,102   $ 46,568   $ 35,990  
Net Income (Loss) Attributable to Common and Class B Unitholders, per unit $ (0.12 ) $ 1.14 $ 0.05 $ 0.80
Plus (less):
Change in fair value of commodity derivative contracts 0.31 (0.86 ) 0.80 (0.38 )
Change in fair value of interest rate derivative contracts

-

(0.05 ) (0.01 ) (0.06 )
Unrealized fair value on phantom units granted to officers

-

0.01

-

0.02
Fair value of derivative contracts acquired that apply to
contracts settled during the period 0.08 0.11 0.15 0.23
Gain on acquisition of oil and natural gas properties

-

(0.08 ) (0.40 ) (0.09 )
Material transaction costs incurred on acquisitions  

-

   

-

   

-

    0.01  
Adjusted Net Income Attributable to Common and Class B Unitholders, per unit $ 0.27   $ 0.27   $ 0.59   $ 0.53  
 
Weighted average common and Class B units outstanding 80,956 71,218 80,285 68,021
 

Contacts

Vanguard Natural Resources, LLC
Investor Relations
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com

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Contacts

Vanguard Natural Resources, LLC
Investor Relations
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com